This invention relates generally to the art of hydraulic fracturing in subterranean formations and more particularly to a method and means for optimizing fracture conductivity.
Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a xe2x80x9creservoirxe2x80x9d) by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbon to reach the surface. In order for the hydrocarbon to be xe2x80x9cproduced,xe2x80x9d that is travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation to the wellbore.
Hydraulic fracturing is a primary tool for improving well productivity by placing or extending channels from the wellbore to the reservoir. This operation is essentially performed by hydraulically injecting a fracturing fluid into a wellbore penetrating a subterranean formation and forcing the fracturing fluid against the formation strata by pressure. The formation strata or rock is forced to crack and fracture. Proppant is placed in the fracture to prevent the fracture from closing and thus, provide improved flow of the recoverable fluid, i.e., oil, gas or water.
The success of a hydraulic fracturing treatment is related to the fracture conductivity. Several parameters are known to affect this conductivity. First, the proppant creates a conductive path to the wellbore after pumping has stopped and the proppant pack is thus critical to the success of a hydraulic fracture treatment. Numerous methods have been developed to improve the fracture conductivity by proper selection of the proppant size and concentration. To improve fracture proppant conductivity, typical approaches include selecting the optimum propping agent. More generally, the most common approaches to improve propped fracture performance include high strength proppants (if the proppant strength is not high enough, the closure stress crushes the proppant, creating fines and reducing the conductivity), large diameter proppants (permeability of a propped fracture increases as the square of the grain diameter), high proppant concentrations in the proppant pack to obtain wider propped fractures.
In an effort to limit the flowback of particulate proppant materials placed into the formation, proppant-retention agents are commonly used so that the proppant remains in the fracture. For instance, the proppant may be coated with a curable resin activated under downhole conditions. Different materials such as fibrous material, fibrous bundles or deformable materials have also used. In the cases of fibers, it is believed that the fibers become concentrated into a mat or other three-dimensional framework, which holds the proppant thereby limiting its flowback. Additionally, fibers contribute to prevent fines migration and consequently, a reduction of the proppant-pack conductivity.
To ensure better proppant placement, it is also known to add a proppant-retention agent, e.g. a fibrous material, a curable resin coated on the proppant, a pre-cured resin coated on the proppant, a combination of curable and pre-cured (sold as partially cured) resin coated on the proppant, platelets, deformable particles, or a sticky proppant coating, to trap proppant particles in the fracture and prevent their production through the fracture and to the wellbore.
Proppant-based fracturing fluids typically also comprise a viscosifier, such as a solvatable polysaccharide to provide sufficient viscosity to transport the proppant. Leaving a highly-viscous fluid in the fracture reduces the permeability of the proppant pack, limiting the effectiveness of the treatment. Therefore, gel breakers have been developed that reduce the viscosity by cleaving the polymer into small molecules fragments. Other techniques to facilitate less damage in the fracture involve the use of gelled oils, foamed fluids or emulsified fluids. More recently, solid-free systems have been developed, based on the use of viscoelastic surfactants as viscosifying agent, resulting in fluids that leave no residues that may impact fracture conductivity.
Numerous attempts have also been made to improve the fracture conductivity by controlling the fracture geometry, for instance to limit its vertical extent and promoting longer fracture length. Since creating a fracture stimulates the production by increasing the effective wellbore radius, the longer the fracture, the greater the effective wellbore radius. Yet many wells behave as though the fracture length were much shorter because the fracture is contaminated with fracturing fluid (i.e., more particularly, the fluid used to deliver the proppant as well as a fluid used to create the fracture, both of which shall be discussed below). The most difficult portion of the fluid to recover is that retained in the fracture tipxe2x80x94i.e. the distal-most portion of the fracture from the wellbore. Thus, the result of stagnant fracturing fluid in the fracture naturally diminishes the recovery of hydrocarbons.
Among the methods proposed to improve fracture geometry, one includes fracturing stages with periods of non-pumping or intermittent sequences of pumping and flowing the well back as described in the U.S. Pat. No. 3,933,205 to Kiel. By multiple hydraulic fracturing, the well productivity is increased. First, a long primary fracture is created, then spalls are formed by allowing the pressure in the fracture to drop below the initial fracturing pressure by discontinuing injection and shutting the well. The injection is resumed to displace the formed spalls along the fracture and again discontinued, and the fracture is propped by the displaced spalls. According to a preferred embodiment, the method is practiced by allowing the well to flow back during at least some portion of the discontinuation of the injection.
Another placement method involves pumping a high viscosity fluid for Pad followed by less viscous fluid for proppant stages. This technique is used for fracturing thin producing intervals when fracture height growth is not desired to help keep the proppant across from the producing formation. This technique, sometimes referred to as xe2x80x9cpipeline fracturingxe2x80x9d, utilizes the improved mobility of the thinner, proppant-laden fluid to channel through the significantly more viscous pad fluid. The height of the proppant-laden fluid is generally confined to the perforated interval. As long as the perforated interval covers the producing formation, the proppant will remain where it is needed to provide the fracture conductivity (proppant that is placed in a hydraulic fracture that has propagated above or below the producing interval is ineffective). This technique is often used in cases where minimum stress differential exists in the intervals bounding the producing formation. Another example would be where a water-producing zone is below the producing formation and the hydraulic fracture will propagate into it. This method cannot prevent the propagation of the fracture into the water zone but may be able to prevent proppant from getting to that part of the fracture and hold it open (this is also a function of the proppant transport capability of the fracturing fluid).
Other methods for improving fracture conductivity are with encapsulated breakers and are described in a number of patents and publications. These methods involve the encapsulation of the active chemical breaker material so that more of it can be added during the pumping of a hydraulic fracturing treatment. Encapsulating the chemical breaker allows its delayed release into the fracturing fluid, preventing it from reacting too quickly so that the viscosity of the fracturing fluid would have been degraded to such an extent that the treatment could not be completed. Encapsulating the active chemical breaker allows for significantly higher amounts to be added which will result in more polymer degradation in the proppant pack. More polymer degradation means better polymer recovery and improved fracture conductivity.
All of the methods described above have limitations. The Kiel method relies on xe2x80x9crock spallingxe2x80x9d and creation of multiple fractures to be successful. This technique has most often been applied in naturally fractured formations, in particular, chalk. The theory today governing fracture re-orientation would suggest that the Kiel method could result in separate fractures, but these fractures would orient themselves rather quickly into nearly the same azimuth as the original fracture. The xe2x80x9crock spallingxe2x80x9d phenomenon has not shown to be particularly effective (may not exist at all in many cases) in the waterfrac applications over the past several years. The xe2x80x9cpipeline fracturingxe2x80x9d method is generally limited by the concentration and total amount of proppant that can be pumped in the treatment since the carrying fluid is a low viscosity polymer-based linear gel. The lack of proppant transport will be an issue as will the increased chance for proppant bridging in the fracture due to the lower viscosity fluid. The lower proppant concentration will minimize the amount of conductivity that can be created and the presence of polymer will effectively cause more damage in the narrower fracture.
The development and application of encapsulated breakers results in significant improvement of fracture conductivity. Nevertheless, there is still a limitation as the amount of polymer recovered from a treatment will often not exceed 50% (by weight). Most of the polymer is concentrated in the tip portion of the fracture, that is the portion most distant from the wellbore. This means that the well will produce from a shorter fracture than what was designed and put in place. In all of the above cases the proppant will occupy approximately no less than 65% of the volume of the fracture. This means that no more than 35% of the pore volume can contribute to the fracture conductivity.
It is therefore an object of the present invention to provide an improved method of fracturing and propping a fracturexe2x80x94or a part of a fracture whereby the fracture conductivity is improved and thus, the subsequent production of the well.
According to the present invention, the well productivity is increased by sequentially injecting into the wellbore alternate stages of fracturing fluids having a contrast in their ability to transport propping agents to improve proppant placement, or having a contrast in the amount of transported propping agents.
The propped fractures obtained following this process have a pattern characterized by a series of bundles of proppant spread along the fracture. In another words, the bundles form xe2x80x9cislandsxe2x80x9d that keep the fracture opens along its length but provide a lot of channels for the formation fluids to circulate.
According to one aspect of the invention, the ability of a fracturing fluid to transport propping agents is defined according to the industry standard. This standard uses a large-scale flow cell (rectangular in shape with a width to simulate that of an average hydraulic fracture) so that fluid and proppant can be mixed (as in field operations) and injected into the cell dynamically. The flow cell has graduations in length both vertically and horizontally enabling the determination of the rate of vertical proppant settling and of the distance from the slot entrance at which the deposition occurs. A contrast in the ability to transport propping agents can consequently be defined by a significant difference in the settling rate (measurement is length/time, ft/min). According to a preferred embodiment of the invention the alternated pumped fluids have a ratio of settling rate of at least 2, preferably of at least 5 and most preferably of at least 10.
Since viscoelastic-based fluids provide exceptionally low settling rate, a preferred way of carrying out the invention is to alternate fluids comprising viscoelastic surfactant and polymer-based fluids.
According to another aspect of the invention, the difference in settling rate is not achieved simply from a static point of view, by modifying the chemical compositions of the fluids but by alternating different pumping rates so that from a dynamic point of view, the apparent settling rate of the proppant in the fracture will be altered.
A combination of the static and dynamic approach may also be considered. In other words, the preferred treatment consists in alternating sequences of a first fluid, having a low settling rate, pumped at a first high pumping rate and of a second fluid, having a higher settling rate and pumped at a lower pumping rate. This approach may be in particular preferred where the ratio of the settling rates of the different fluids is relatively small. If the desired contrast in proppant settling rate is not achieved, the pump rate may be adjusted in order to obtain the desired proppant distribution in the fracture. In the most preferred aspect, the design is such that a constant pump rate is maintained for simplicity.
As an alternative aspect the pump rate may be adjusted to control the proppant settling. It is also possible to alternate proppants of different density to control the proppant settling and achieve the desired distribution. In even another aspect the base-fluid density may be altered to achieve the same result. This is because the alternating stages put the proppant where it will provide the best conductivity. An alternating xe2x80x9cgood transportxe2x80x9d and xe2x80x9cpoor transportxe2x80x9d is dependent of five main variablesxe2x80x94proppant transport capability of the fluid, pump rate, density of the base-fluid, diameter of the proppant and density of the proppant. By varying any or all of these, the desired result may be achieved. The simplest case, and therefore preferred, is to have fluids with different proppant transport capability and keep the pump rate, base-fluid density and proppant density constant.
According to another embodiment of the invention, the proppant transport characteristics are de-facto altered by significantly changing the amount of proppant transported. For instance, proppant-free stages are alternated with the proppant-stages. This way, the propped fracture pattern is characterized by a series of post-like bundles that strut the fracture essentially perpendicular to the length of the fracture.
The invention provides an effective means to improve the conductivity of a propped hydraulic fracture and to create a longer effective fracture half-length for the purpose of increasing well productivity and ultimate recovery.
The invention uses alternating stages of different fluids in order to maximize effective fracture half-length and fracture conductivity. The invention is intended to improve proppant placement in hydraulic fractures to improve the effective conductivity, which in-turn improves the dimensionless fracture conductivity leading to improved stimulation of the well. The invention can also increase the effective fracture half-length, which in lower permeability wells, will result in increased drainage area.
The invention relies on the proper selection of fluids in order to achieve the desired results. The alternating fluids will typically have a contrast in their ability to transport propping agents. A fluid that has poor proppant transport characteristics can be alternated with an excellent proppant transport fluid to improve proppant placement in the fracture.
The alternate stages of fluid of the invention are applied to the proppant carrying stages of the treatment, also called the slurry stages, as the intent is to alter the proppant distribution on the fracture to improve length and conductivity. As an example, portions of a polymer-based proppant-carrier fluid may be replaced with a non-damaging viscoelastic surfactant fluid system. Alternating slurry stages alters the final distribution of proppant in the hydraulic fracture and minimizes damage in the proppant pack allowing the well to attain improved productivity.
According to a preferred embodiment, a polymer-based fluid system is used for the pad fluid in these cases in order to generate sufficient hydraulic fracture width and provide better fluid loss control. The invention may also carried out with foams, that is fluids that in addition of the other components comprise a gas such as nitrogen, carbon dioxide, air or a combination thereof. Either or both stages can be foamed with any of the gas. Since foaming may affect the proppant transport ability, one way of carrying out the invention is by varying the foam quality (or volume of gas per volume of base fluid).
According to a preferred embodiment, this method based on pumping alternating fluid systems during the proppant stages is applied to fracturing treatments using long pad stages and slurry stages at very low proppant concentration and commonly known as xe2x80x9cwaterfracsxe2x80x9d, as described for instance in the SPE Paper 38611, or known also in the industry as xe2x80x9cslickwaterxe2x80x9d treatment or xe2x80x9chybrid waterfrac treatmentxe2x80x9d. As described in the term xe2x80x9cwaterfracxe2x80x9d as used herein covers fracturing treatment with a large pad volume (typically of about 50% of the total pumped fluid volume and usually no less than where at least 30% of the total pumped volume), a proppant concentration not exceeding 2 lbs/gal, constant (and in that case lower than 1 lb/gal and preferably of about 0.5 lbs/gal) or ramp through proppant-laden stages, the base fluid being either a xe2x80x9ctreated waterxe2x80x9d (water with friction-reducer only) or comprising a polymer-base fluid at a concentration of between 5 to 15 lbs/Mgal).